North America

Published at 16:40 6 Dec 2018 by . Last edited 11:18 22 Aug 2019.

We forecast that US LNG exports will grow by 2.8 Mt y/y to total 11.8 Mt in Q4 18–Q1 19 as Cheniere’s Corpus Christi T1 and Sabine Pass T5 continue to ramp up. Over Q1 19 alone, we see the US adding some 1.0 Mt y/y to supply, based on a relatively slow ramp-up for new trains. For the US, we project gas in storage at end-March 2019 to be 1.3 tcf (36.8 bcm), which is low enough to raise concerns about meeting demand if there is end-of-season cold weather and could require heavy injections in summer 2019 if March inventories were to drop further. We forecast heavy y/y production growth of 6.6 bcf/d (0.19 bcm/d) in 2019, but demand also looks very robust going forward—we expect a combined 3.5 bcf/d (0.1 bcm/d) in y/y demand growth in 2019 from LNG feedgas, exports to Mexico and greater industrial use. We expect storage carry-out in end-October closer to 3.6 tcf (102 bcm), as the market will want a higher carry out than end-October 2018. Notwithstanding some significant moving parts, we see Henry Hub prices over Q2 19–Q3 19 easing back significantly from current levels of over 4 $/mmbtu and toward 2.80 $/mmbtu.

With global LNG prices trading at a considerable premium to Henry Hub across the curve, possible Henry price spikes due to deliverability concerns late this winter will not have a significant impact on US LNG export levels. Volumes from Cove Point could be at risk, however, as local feedgas prices trade at a premium, which may make it uneconomical to export Cove Point gas. Feedgas volumes into Cove Point remained steady near 0.75 bcf/d (21.2 mcm/d) last month, essentially at full utilisation, but cash prices at the nearby Transco Z5 (TZ5) are still sub-6 $/mmbtu, keeping global arbs open.

We estimate variable transport costs to India from Cove Point of around 2.4 $/mmbtu—an ex-ship India-TZ5 spread below which Cove exports become uneconomic. With the JKM curve dropping below 10 $/mmbtu for the Jan–Feb contracts, and peak winter delivery on TZ5 pricing up above 8 $/mmbtu, that forward spread is now below 2 $/mmbtu, making it more economic to leave the gas in the NE US market. With the TZ5-Leidy peak spread at 3.5–4.0 $/mmbtu for Jan–Feb 19 contracts, GAIL could finance its tolling costs at Cove Point by selling the gas into the TZ5 hub. Even if the India-TZ5 arb were to re-open, which would need TZ5-Leidy to widen, Cove Point volumes could still drop. For GAIL, the decision is ultimately dependent on how much gas it must supply to the domestic Indian market. With European gas prices for summer delivery over 7 $/mmbtu, and with variable transport costs between the Gulf of Mexico and NW Europe near 1.8 $/mmbtu, the arb remains open for US exports in summer 2019.

US gas production growth to continue

While one-off factors appear to have muted sequential production gains in November to 0.8 bcf/d (22.7 mcm/d) m/m, they did not stop US gas from setting another production record. We still anticipate a remarkably heavy baseline production growth of 9.5 bcf/d (0.3 bcm/d) this winter. Some of that y/y growth reflects the impact of freeze-offs last winter. Given near 5 bcf/d (0.1 bcm/d) y/y November gains in Appalachia and Permian output combined, a proportionally similar number of freeze-offs would risk a much larger absolute volume of potential losses this winter—but that is weather-dependent and a further source of potential price support.

Q3 18 earnings calls occurred before the most recent run-up in prices and contained plans for conservative capital budgeting. Our survey of producers pointed to 2019 hedging near $3.10/mmbtu. Depending on the day, the 2019 strip has now ranged $3.15-3.25/mmbtu in the past several trading sessions. According to the Swap Data Repository (SDR) report, some producers have been taking advantage of the recent rally to put on last-minute Cal 19 hedges at higher levels. For several weeks, we observed Cal 19 hedges with prices ranging from $3.04 to $3.25/mmbtu, with several transactions over $3.20/mmbtu. While a nickel might not be enough to change plans, 15 cents could encourage more output. Our survey showed that 50% of volumes from publicly traded producers were hedged, but that does not include the private producers with growing shares in regions like the Haynesville. Our injection season 2019 outlook currently sees near 6.6 bcf/d (0.19 bcm/d) y/y production growth.

Big swinging demand

November showcased how much an early onslaught of cold can tighten balances and also significantly push up winter curve prices. This November saw some of the highest cash prices for the month in years, reflecting the significant reduction in working gas inventories on that early cold. Weather-aided demand was supplemented by underlying growth in three key pillars of structural demand—LNG feedgas, Mexican pipeline exports and industrial gas use.

Our gas burn forecast for summer 2019 has risen amid continued coal retirements and stickiness in gas-fired generation. However, for the injection season, this still amounts to some 0.5 bcf/d (14.2 mcm/d) y/y growth, meaning that structural demand will be a key driver of gas consumption. We forecast that the three structural demand factors—LNG feedgas, Mexican pipeline exports and industrial gas use—will increase by a combined 3.0 bcf/d (84.9 mcm/d) y/y this winter and a further 3.7 bcf/d (0.1 bcm/d) during the summer period.

For the LNG projects, timing risk this heating season is minimal, especially given what we know about the current status of LNG projects—namely that ramp-up is taking place at Corpus Christi and Sabine Pass, and there are delays at Elba Island. The ultimate schedule of ramp-up at the first train at Cameron LNG still has some timing risk surrounding it, but the volumes would be minor for the heating season given an early 2019 startup would only include minor initial feedgas. Risk to the timing of domestic Mexican pipelines remains acute but is already built into our forecasts. Still, risk around weather this heating season trumps infrastructure timing risk, although infrastructure timing will again come to the fore in the 2019 injection season. In spite of the heavy slate of demand growth expected this winter and in the upcoming summer period, the US market still looks balanced enough to be able to supply as much LNG as the global market can accept.

Fig 1: 2018-19 heating season prices, $/mmbtu Fig 2: 2019 injection season prices, $/mmbtu
Source: Reuters, Energy Aspects Source: Reuters, Energy Aspects

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